Embodiments of the present disclosure provide an apparatus and method for non-invasively logging the flow of perforations in a wellcasing lining a wellbore.
After drilling a well into subterranean formations for hydrocarbon recovery, wells are “completed”. Typical well completion involves the insertion of a metal casing into the well, which is then cemented into place by pumping cement along the inside of the metal casing and up into the annular gap that exists between the formation and the casing. The purpose of this is several fold; it provides wellbore integrity, preventing wellbore collapse, as well as isolating the different parts of the formation from one another and with the wellbore. The casing and the cement sheath are then selectively perforated with explosive charges at desired zones. These zones are areas where fluid is produced from (or fluid is injected into). Typically these are the hydrocarbon bearing zones.
There are many parameters that can be varied in the perforation strategy in order to optimise production from a given formation, but it can be difficult to know whether the best strategy has been adopted or not. One way it can be assessed is later, through production logging, where a logging tool is inserted into the flowing well and the total flowrate measured at points along the wellbore.
FIG. 8 exemplifies such a known method. In FIG. 8, a downhole logging tool 100 is provided on a wireline 102 and lowered down a wellbore, typically with a well casing 104 lining the wellbore. As shown, a number of groups of perforations P1, P2 may be provided in the wellbore. Three measurement regions, denoted by A, B, C in FIG. 8, correspond to locations where the flowrate is measured by the downhole logging tool 100.
From the differences in flowrate between two points (e.g., B-A, C-B, or C-A), the incremental flow into the well via the collection of perforations in between can be estimated. This gives a relatively coarse measurement of perforation flow (being averaged over some length) and gives no information on a perforation-by-perforation basis that might indicate whether the direction or azimuth of the perforation influences productivity. This is also evident when two perforations are provided at opposite sides of the well casing 104, for example. Furthermore, at some deviations of the wellbore (i.e., when the wellbore is inclined, being somewhere between vertical and horizontal), there can be very strong gradients in fluid velocities and fluid holdup within the wellbore. This makes conventional production logging velocity measurements inaccurate (adding significant uncertainty to the estimates of inflow through the zone).
The concept of using pulsed wave ultrasonic Doppler to measure the flow out of oilfield perforations has been discussed in an SPE paper (SPE29544), “Characterizing Flow Through a Perforation Using Ultrasonic Doppler” by M. Razi, S. L. Morriss and A. L. Podio, 1995. However, since then the idea has not materialised into a commercial downhole tool. A main technical challenge for perforation flow measurement is how to align an ultrasonic transducer on a downhole tool to the centre of the perforation.
One solution is to use a motor driven rotation head that carries a transducer to perform an azimuthal scan, and this is the method used in a number of ultrasonic based borehole inspection tools, such as the UCI developed by Schlumberger, for example. Many of these prior art systems do not detect individual perforations and/or the flow from or into perforations, and these systems also detect general flow properties of fluid within the wellbore and/or structural properties of the well casing. Such an example of a rotating tool head for imaging a borehole wall is disclosed in EP 0 513 718 A2. However, a design involving moving parts and a downhole motor has reliability and cost issues and is highly undesirable. This is particularly the case when fluid flows through the well causing drag/resistance to the moving parts of the tool head, thereby adding strain to the moving parts and increasing the wear.
Another solution may be based on ultrasonic phased arrays similar to those used for medical imaging, which can perform beam forming and azimuthal scan, controlled entirely by electronics. This removes the need for mechanical moving parts. However, this technique may not be readily appropriate for production logging applications. Such systems involve a large number of transducer elements (in some cases, this may be over 1000), each of which is a few square millimeters in size, and provided in a grid or matrix type arrangement around a tool body forming a shell-type array. During measurements, large numbers of transducer elements need to be grouped together to form a beam that ideally focuses on a casing, wherein different groups are sequentially selected to scan the beam azimuthally. The small size of the transducer elements themselves, the small separation distances therebetween, and the vast number of transducer elements, requires many electrical connections, which raises reliability issues, particularly when exposed to the environments within the wellbore. The complexity and the cost of the system are also major concerns. Furthermore, the design of these systems is heavily dependent upon the wellbore diameter and packing the electronics within a production logging tool adds further complexity and challenges to the design. Moreover, when employed in a production logging tool, the small radius thereof leads to a large surface curvature of the transducer elements, meaning that it becomes more difficult to group transducer elements together to form the desired beam. This can limit the focal distance of the tool meaning that large diameter casing cannot be imaged.
EP 1 348 954 A1 discloses an array of transducers positioned around a cylindrical body, wherein the transducers are used to survey the well casing via beam steering. Properties of the fluid, particularly the composition, can be determined through a pitch/catch geometry. The transducers are arranged monolithically (in an n×m matrix) so as to enable the steering of beam in the vertical direction by applying delays to each of the transducers. This array comprises a large number of transducer elements, and the focal distance must be taken into consideration.
U.S. Pat. No. 7,784,339 discloses a perforation logging tool and method that specifically measures properties of perforations using an array concept. The embodiment uses a flexible array of sensors on a wire mesh expandable screen that is to be pressed against the wall of the casing. Such a system uses non-acoustic and non-Doppler sensors (particularly; hot film flow sensors, temperature, fluid conductivity, dielectric, chemical, viscosity, density and stress (piezoelectric)), and is arranged such that the sensors are positioned proximate to and intimately with the perforations.
There exists a need, therefore, for detailed logging on a perforation-by-perforation basis, regardless of wellbore orientation and size, in order to reveal how well the perforations are performing. Preferably, this will allow the perforation strategy within a given formation to be refined.
Moreover, there exists a need for a practical implementation of ultrasonic Doppler measurements of perforation flow in the demanding downhole environment that uses a much reduced number of transducer elements but allows for a combination of good azimuthal resolution with design simplicity. Furthermore, a non-invasive means for obtaining measurements is required, thus providing more reliable measurements of flows from perforations.